SPE 97589 HPHT Completion Challenges Ron Zeringue, SPE, Shell Exploration & Production Co.
Copyright 2005, Society of Petroleum Engineers Inc. This paper was prepared for presentation at the SPE High Pressure/High Temperature Sour Well Design Applied Technology Workshop held in The Woodlands, Texas, U.S.A., 17-19 May 2005. This paper was selected for presentation by an SPE Program Committee following review of information contained in a proposal submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to a proposal of not more than 300 words; illustrations may not be copied. The proposal must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.z`
Abstract The industry makes a pioneering discovery: 20,000 psi SITP, 100 ppm H2S, 10 % CO2, 400 oF flowing wellhead temperature. Now what? • Everyone wants production as soon as possible. • What challenges need to be overcome? • What equipment is available, and what needs to be designed and tested? • How long will it take to design, build, test (and redesign, re-test), certify, and deliver? • What challenges have yet to be identified? • If you have a failure, can you work it over? • Is there well control equipment in place? Recent HPHT history indicates that infantile failures happen, usually caused by something that no one considered an issue. What are the hidden obstacles awaiting the first ultra HPHT completion? This paper will summarize current industry HPHT capability and more importantly, propose questions in an attempt to stimulate discussion on issues that we may be missing. HPHT Completion Challenges Industry is currently drilling wells to severe HPHT conditions, e.g., SITP 20 ksi, BHT 470 oF, 25,000 ft depths. One day someone may have the chance to complete one of these monsters! Of course, everyone will want production ASAP. Two critical questions occur: • What are the technology gaps? • WHAT ARE ISSUES THAT WE HAVEN’T EVEN THOUGHT ABOUT?
Considering the latter question, “Will we miss something?” • The first ultra HPHT completion will be full of Serial # 1 equipment. • History has shown that infantile failures (well failures in the first few months of production) are more likely with new equipment designs and service conditions. Infantile failures have been caused by: o A corrosion inhibitor. o A hard spot missed by convential inspection methods. o A material good for the Aerospace industry, not working in an oil field environment. o A thread failure We can handle (I think!) the snakes we can see, but what about those hidden in the weeds! Table 1 shows well conditions for several “typical HPHT” wells.
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Table 1 – Well Conditions For Several “Typical HPHT” Wells SITP, psi BHP, psi Well Depth, ft Surface flowing temp F
15,000 17,000 18,000 335
18,500 22,000 23,000 400
20,000 24,000 25,000 410
23,000 27,000 28,000 425
25,000 30,000 32,000 450
385
450
465
500
530
H2S pp, psi
0.6
3?
4?
7?
11 ?
CO2, %
5
18 ?
21 ?
?
?
BHT, oF
Assumptions • SITPs indicate approximate step changes in completion degree of difficulty. • Pressure gradient of 18.4 ppg, SITP = 0.85 * BHP • Temperature gradient of 1.5 oF/100’ • H2S and CO2 values based on extrapolation of published correlations, Smith for H2S and Bross for CO2. To assess the challenges we will encounter in this arena, well completion issues and components will be covered in the following sections. The time-to-acquire and degree of difficulty for each type of equipment has been estimated, and is described in color format according to the key shown in Table 2. Table 2 – Color-Coded Key Descriptions Green - Existing equipment. Delivery times in years Yellow - Limited sizes or not available, but designs indicate no major hurdles. Time in years for design,testing and delivery. Pushing limits of current technology. Time in years for R & D, design,testing and delivery. Major technical breakthrough required. Time in years for R & D, design,testing and delivery. • • • •
█ Green – been there, done that, can do again. Delivery time in years for equipment with > 4 month delivery. █ Yellow – sure it can be done, but either have not done yet or very limited experience. Estimated time in years for design, testing and manufacturing. █ Orange – think that it can be done with current technology. Estimated time in years for R & D, design, testing and manufacturing. █ Red – major technical breakthrough required. Estimated time in years for R & D, design, testing and manufacturing.
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HPHT CHALLENGES AND GAPS Table 3 summarizes the gaps and expected lead times to develop equipment for shelf HPHT wells. Table 3 – Gaps and Expected Lead Times SITP, psi BHP, psi Well Depth, ft Surface flowing temp F
15,000 17,000 18,000 335
18,500 22,000 23,000 400
20,000 24,000 25,000 410
23,000 27,000 28,000 425
25,000 30,000 32,000 450
BHT, oF
385
450
465
500
530
H2S pp, psi
0.6
3?
4?
7?
11 ?
CO2,%
5
18 ?
21 ?
?
?
CASING
1.0
1.0 - 1.5
1.5 – 2.0
2.0 – 2.5
?
CASING CONNECTION
1.0
1.5 – 2.0
2.0 – 2.5
?
TIE-BACK SYSTEMS & LINER HANGERS
1.0-1.5
1.0-1.5
1.0-1.5
1.0-1.5
1.0 -1.5
1.5 - 2.0
1.5 - 2.0
2.0 – 3.0
0.5
0.5 - 1.0
1.0 - 2.0
2.0 – 3.0
0.5 - 1.0 0.5 - 1.0 1.5
1.0 1.0 2.0 - 2.5 1.0
1.0 - 1.5 1.0 - 1.5 3.0 1.5
2.0 - 3.0 1.0 - 1.5 3.0 2.0
0.5? 0.5?
0.5 0.5
1.0 - 2.0 1.0 - 2.0
1.5
1.5
? 2.0
2.0 1.0 ? 2.0
? ?
? ?
1.5 1.0 2 - 2.5 1.0 - 2.0 ? ? ? ? ? ?
1.5 1.5 3.0 1.0 - 2.0 ? ? ? ? ? ?
1.0 - 2.0 1.0 - 2.0 0.5 ? 1.5 – 2.0 3.0 2.0 - 3.0 ? ? ? ? ? ?
TUBING
1.0 - 1.5
TUBING CONNECTION PACKER SCSSV WELLHEAD/TREE PERFORATING - TCP
0.5 0.5 0.5 - 1.0
PERFORATING ELECTRIC LINE LUBRICATORS CABLES TUBING CUTTERS PLUGS BOP KILL PUMPS & PIPING COMPLETION FLUIDS RELIEF WELLS SNUBBING UNITS COIL TUBING SAND CONTROL FRACTURING
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Casing Materials And Connections Tieback casing design and sour service material qualification is the critical path issue for ultra HPHT completions. Other authors cover this topic extensively in the May 2005 SPE HPHT ATW. Issues include: • Qualification of high strength carbon steels for the expected pressures, temperatures, and environment. • Connection design and testing. • Nickel based CRAs may be a solution, but have never been made in the sizes required. • Tieback weight may be beyond capacity of most rigs. Tieback may have to be run in sections. • What casing test pressure is required on initial completion – SITP? Requires BOPs rated to SITP or test the casing with the tree installed. • For connection qualification, should external gas testing be performed? o During completion operations, connections will be exposed to large differentials with lightweight completion fluids. o If multiple productive zones are encountered, connections may be exposed to large differentials with lightweight packer fluids. o Are heavy weight completion fluids the answer or do they just bring other problems? o Are there appropriate facilities for external gas testing? o Another potential benefit of dual seal connections, keep the external pressure off the pin nose seal. • Tieback systems and liner hangers o Current tieback systems and liner hanger packers rated to maximum 20 ksi and 400 oF. o Temperature issues to achieve 500 oF +. Build Test fixtures rated higher than 500 oF. Metal-to-Metal technology needed to eliminate elastomers, existing Metal-to-Metal technology not tested to 500 degrees. Metal properties may be altered. Expanding and contracting issues unknown. o Tieback system to hold 30,000 PSI and not rely on cement. Maintaining ID requires skipping casing size (7⅝ in. x 11¾ in.). Hydraulics must be isolated after tieback. Cementing of tieback critical to anchor system to minimize movement. May require complete new design. Test fixtures capable of 30,000 PSI need to be designed and built. Safety concerns. o Design and testing timing 12-18 months. • Cementing Issues – can we get good cement jobs? o Top of cement in tieback may be critical to completion design and potentially limit production rates. o Isolation requirements. o Trapped annular pressure issues.
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Long term stability and ability to withstand multiple temperature and pressure cycles.
Tubing And Connections Nickel based alloys have been used successfully in many HPHT applications. However, for ultra HPHT wells, other concerns exist, including: • Nickel based alloys such as SM 2550, G50, C276 will likely work but have not been tested above 450 oF. o Testing of these alloys with a constant strain test will require 6 to 10 months. o SSRT’s are shorter, but does it provide accurate results? Shell does not recommend this test for this application because it does not capture initiation effects like pitting that is a concern with CRAs. o Have these alloys been tested in heavy weight brines at elevated temperatures (workover contingency)? o How about pH effects? Possible scale issues if the wells make water. Will the alloys stand up to remedial acids jobs to remove scale etc. at these higher temperatures? o Mills may not commit to order until internal testing done – lead-time could be longer. • Current lead-time for nickel-based alloys is 12–18 months. Lead time and costs going up! • Titanium Tubing? o A possibility, but could have connection issues. o No history of use in HPHT wells, any snakes in the grass? o Will acid compatibility be an issue? • Connection testing will be required for initial ultra HPHT completions. o Can sufficient amounts of material be obtained from the mills for connection tests prior to delivery of the order? o If not, delivery times are the sum of the Tubing and Connection times. o Standardization of sizes and connections would be a plus. o Tapered tubing strings may be required due to casing constraints, but there will be severe bending loads on smaller string. Packers Packers have been designed and tested for 15 ksi applications, but sizes are limited. Only one packer has been designed for 20-ksi service. • Limited sizes currently are available. o 20 ksi – 7⅝ in., 55.3#. • Packers should be run with completion tubing and set either hydraulically or hydrostatically. o Allows for a metal-to-metal back off sub or metal-tometal threaded connection to packer. • What pressure rating is required? Should it be equal to the bottom hole pressure or expected differential across packer plus a safety factor to account for kill operations, acidizing etc.
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Test procedure – ISO V0 – Is this enough? Should we also test with cyclic loads? Test facilities are limited to 460 oF and 20 ksi. Significant investment required for higher temperatures and pressures. Limited setting range on HPHT packers. o May require honed or extremely tight casing tolerances to get differential rating. Casing stress caused by packer and tubing could be critical if casing is unsupportive. Milling of CRA packers is extremely difficult. Loss of well a possibility. What are the temperature limits of Inconel 718/725? o At high temperatures Inconel 718/725 becomes susceptible to corrosion and environmental cracking when exposed to certain agents. Aging may be an issue. o Testing needs to include exposure to heavy weight brines or cesium formates. o What is the temperature effect on strength?
SCSSVs Again, limited work has been done on SCSSVs, but not at the ultra HPHT conditions above 20 ksi. • Limited sizes currently available with pressure rating greater than 15 ksi. o 4.5 in., 20 ksi – OD 7.13 in., ID 3.437 in. o 3.5 in., 20 ksi – OD 5.49 in., ID 2.313 in. o 3.5 in., 16.7 ksi - OD 5.65 in, ID 2.87 in. • With API 14A requirement of a test pressure of 1.5 times the working pressure, maximum pressure rating is 20 ksi and 400 oF due to verification test limits at Southwest Research. Standard currently under review to reduce test pressure to 5000 psi above working pressure for SCSSVs of 10 ksi and greater. Awaiting final committee approval and MMS approval. • Is more than one SCSSV needed? • Does the slam test requirement in API 14 A provide a sufficient test? o Rate is low in regulations (for instance 17.3 MMCFPD for a 3.5 in. valve), but what should be done for prudent operations (absolute open flow AOF, maximum expected rate, etc?). o Slam testing is done at atmospheric conditions. Would a low rate high-pressure slam test better simulate what would happen in a real emergency? Test facilities do not exist for this type of testing. • SCSSVs require high strength (140 ksi) inconel 718/725. o Very hard to obtain, typically requires hand picking pieces. • ID/OD constraints are critical. o OD needs to be minimized to fit in tie back strings and potentially BOP bores. o ID needs to be maximized to allow for electric line operations, especially pipe recovery and perforating. • What are the temperature effects on control line fluids and dynamic seals? o Degradation of control line fluid and dynamic seals over time needs to be evaluated.
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Will dynamic seals be reliable at 25 ksi + and high temperatures? Will control line connections be reliable long term at 25 + ksi with thermal changes. o How about the control line itself? o Have to take into account the maximum control line pressure required in tree design for pass through and outlet valves. There is an alternate valve design that may alleviate some of the issues of high-pressure control lines, but this design is currently not available in pressure ratings required and has not been field proven to date.
Wellhead And Tree HPHT wellheads, 20 ksi and some 30 ksi, have been built. Most of the 30-ksi equipment was for land wells. These wells were mostly low rate, < 20 MMCFPD. The conditions and expected high rates of ultra HPHT wells will create new issues. • 20 ksi, 350 oF clad trees and wellheads are available – 6 months to 1-year lead-time required. • New design or qualification testing required if >350 oF and 20 ksi for: o Tubing spools o Back pressure valve prep o Stem packing o Gate valves and seats o Chokes • Major qualification hurdle will be stem packing at temperatures > 350 oF and pressures >20 ksi. o Difficult to pass qualification test, which requires temperature, cycles from 0 oF to maximum temperature. o Reduction in material strength will also have to be determined for temperatures > 350 oF. • What is the long term reliability of gates, seats and hard surfacing? • A positive and adjustable choke in series will be required to handle pressure drops. Perforating And Electric Line Three options exist for perforating. TCP guns can be installed below the permanent production packer, and then detonated after the tree is installed. The well can be perforated through tubing either with multiple wireline runs, or guns can be hung off and fired hydraulically. TCP • Gun systems, carriers and firing heads currently rated to ~ 24 ksi and 450 oF. • HNS guns systems good for only 107 hrs at this temperature. • Development of a contingency plan to perforate if TCP guns don’t work is required. o Can guns be dropped off? o Difficult to mill up CRA packers and unlikely to be able to cut tubing to drop guns. • If we drop the tubing string or if guns fall off while running in hole, will guns fire? Since it is likely
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SPE 97589
completion fluid will not be kill weight the risk is very high, even though the probability occurrence is low. QA/QC and testing of gun system is critical to insure performance.
Electric Line Perforating • Difficult to get both pressure and temperature ratings with size limitations due to tubing and SCSSV restrictions. • Gamma Ray correlation tools and PIP tags will be required due nickel alloy production liners. Current rating is 25 ksi and 500 oF for one hr. Lubricators And Cables • Limited availability of 20-ksi lubricators. Six month lead time for new 20-ksi equipment, however, vendor safety standards typically limit use to 80% of rated working pressure. o Lead time for development of 30-ksi equipment (1 to 2 years). • Limited availability of MP35 N cables. Long lead time for new cables. Cables currently rated to 500 oF. Minimal over pull available at depths > 22,000 ft. Tubing Cutters No cutters currently on the market can reliably cut high strength, thick walled nickel alloy tubulars at ultra HPHT conditions. • Cannot test cutters under well conditions due to test facility limitations. Tools are typically tested thermally first, then fired under pressure at ambient temperature. • Available test facilities include: o Navy Gun: 30,000 psi working pressure (but ambient temperature only, does not have thermal capability). Inside bore is 14 inches x 82 inches deep. Max. explosive amount allowed is 125g. o HPHT Chamber: 20,000 psi working pressure @ 400 F. Inside bore is 7.5 inches x 162 inches deep. Max. explosive amount allowed is 70g. • Radial Cutting Torch o 500 deg F and 10 ksi currently qualified, 15 ksi cutters under development with some sizes currently available. Plans are to develop 20 ksi tools in the future. o Successful cuts can be achieved with tool ODs smaller than with other types of cutters. (ie 111/16 in. tool for 2 ⅞ in., 7.9 #; 2 in. tool for 3.5 in., 12.95 #) o Successful cuts on nickel alloy tubulars have been made with 10 ksi rated tools. o There have been instances where the tool or parts of the tool are lost in hole when used near the pressure rating. Performance has improved over the years. o Need to test high-pressure cutters on nickel alloy tubing such as C276, 825, SM2250 etc. • Jet Cutters o 400 degrees for 1 hour with HMX at approximately 20 ksi. o Size that can be run limited by ID of safety valves. Tools near the ID of the tube usually required for
successful cuts. Can make cutters with higher temperature explosives but performance goes down. o For HPHT applications, cutters would likely have to be designed and tested based on actual temperatures and pressures and metallurgy of tubular goods. Chemical Cutters o Limited to 350 degrees and 20 ksi with the same size limitations as jet cutters. o
•
Plugs • Limited sizes of slickline plugs available with ratings above 15 ksi and 400 oF. Well Control Well control in the event of an infantile failure is a major gap HPHT completion technology. • Limited 20 ksi BOPs stacks and choke manifolds. Stacks have not been used in years and may need reconditioning. It will require two years for new BOP stacks. No equipment available for pressures > 20 ksi. Is it prudent to complete a well without having a BOP stack available that can handle maximum SITP? • Can the shear rams shear the heavy wall, high strength tubulars that will be run? • Well kill - Currently limited availability of 20 ksi equipment and none available for pressures > 20 ksi. Pumps, piping, chicksans, or coflexit would have to be developed, 1-2 year’s delivery. Is it prudent to complete a well without having equipment rated to the maximum SITP available in industry for an emergency kill? • Height and weight of BOPs, wellheads, choke manifolds etc. will be larger then what is currently used and may require special handling equipment. • Kill weight completion fluids. o Can heavy weight brines be inhibited at these high temperatures? Corrosion inhibitors for ZnBr tend to degrade to H2S and zinc sulfide scales. Needs to be tested with CRAs, elastomers, high strength work strings etc. o Are Cesium formates the answer? o Oil base mud will work, but there are issues. OBM can destabilize and the weighting agent drop out over time plugging the tubing, complicating future work over. Clean out of the weighting agent with coiled tubing difficult due to low pump rates. Potential for severe formation damage. Limited ability to clean up formation damage with stimulations due to pressures and temperatures. • Relief wells - Temperature limit of 350 oF of magnetic proximity tool for detecting blowout well would limit relief well depth. Deepest relief well to date is around 22,000 feet. • How do we want to configure the trees/wellheads for emergency kill operations? Topsides design and layout needs to address tree leaks, fires and emergency kill access.
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Completion planning should include developing contingency kill plans and insuring equipment availability prior to first production.
Remedial Operations Remedial operations are not normally planned as part of an initial completion. However, for ultra HPHT wells contingency planning will be required. • Snubbing Units – maximum rated snubbing units are 20,000 psi. • Coiled tubing – maximum rating 15 ksi and 400 oF. • Workstrings. o Heavy wall tiebacks and liners will limit workstring sizes and torque ratings. May not be able to wash over. o S-135 workstrings can be used in inhibited mud or completion brines before perforating (i.e. no H2S), but can heavy weight completion brines be inhibited sufficiently for use of S-135 for remedial operations? o Premium connections such as XTM40 or PH6 will be required. These connections are very susceptible to pitting on MTM seal face in heavy weight brines. o Workstrings that are sour gas compatible are in limited supply and may not have sufficient strength. Long lead time required for new strings. • Sand Control – not any time soon! o It is likely that formations will be competent initially. o Remedial sand control may be possible after depletion, but would have to be taken into consideration in initial completion. Small liners, CRA packers to mill up, temperatures, and poor cement jobs are all issues to be considered. • Fracturing – not anytime soon! o Issues with fluids, packer loads, surface pressures etc. o May be possible after depletion, but would have to be taken into consideration in initial completion. Integration And Production Operations Good communication between drilling, completion, facility, and production personnel is critical to insure successful handoffs. • How many wells do you want on a platform? Should independent jackets be used if water is shallow enough? • Wellhead growth o Accurate modeling wellhead growth is required for proper facility and flow line design. o Shell has experienced growth below the mud line, especially if several wells clustered together. o Will casing growth put unexpected loads on conductor casings? • Understanding and managing annular pressures o The effect of trapped annular pressures due to trapped fluids between cement needs to be addressed. o “A” annulus pressures can be reduced by putting N2 blanket This reduces the need to bleed off annular fluid and reduces the risk of getting oxygen into the annulus during shut in. N2 blanket reduces hydrostatic head, thus
o o
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increasing external pressure differential on casing connections. Operations personnel need to have guidelines to maintain the desired backpressure on the annulus. “B” annulus pressures can be affected by thermal and communication with zones Mud degradation and thermal affects can cause micro-annuluses in cement. Shell has experienced “B” annulus pressure due to flow from tight noncommercial zones. Possibility of corrosion issues. Testing of casing hanger seals in both directions is required to prevent seal failure from outer to inner strings of casing.
Conclusion The industry has completed HPHT wells in the past. However, the new higher temperature and pressure horizons being drilled today will require an industry-wide technology and development effort in order to deliver a reliable completion. These new ultra-HPHT completions will tax our industry resources – people and infrastructure – to deliver a safe completion in a timely fashion. As a result of our past efforts, we are confident that the technology to complete these wells can be made available. However, many of those who pioneered this effort are no longer active. There has not been a recent, strong industry focus on HPHT wells and we are at risk of losing industry knowledge if we do not work to capture our past learnings. There is a stronger need than ever before to pool our efforts in preparing for the new HPHT future. Acknowledgements I would like to thank the management of Shell Exploration and Producing Company for the opportunity to prepare and present this paper. I would also like to extend my appreciation for the input into this project by other Shell personnel and numerous equipment suppliers.
